There will be a replay available on our website later on today. All attendees have been placed in listen-in-only mode for the duration of the webcast, but we will be hosting a Q&A session at the end of the presentation. If you have any questions, you can use the Zoom Q&A button to submit those. Alternatively, if you're listening in on your phone, you can send any questions to social media at alvopetro.com. Lastly, just a reminder, we do go through various non-GAAP measures, and we make forward-looking statements and go through some other reserve metrics.
We are not going to go through all of that in detail, but we do encourage you to read the cautionary statements and other disclosures that are at the end of our presentation posted on our website, or all the calculations are in more detail in our MD&A, which we just released yesterday.
Thank you, Alison. To start off, this chart obviously shows our production since we started natural gas sales from our Caburé project in July of 2020. Reminder, our pre-commercialization guidance was equal to our firm sales to Bahiagás at the time, which was also equal to the unit productive capacity multiplied by our working interest at the time, which was about 1,800 barrels of oil equivalent per day, which was pretty consistent with the second half of 2020 production. You can see we went through a period of time where we significantly exceeded that guidance as we were selling flexible and interruptible gas to Bahiagás. We also expanded our gas plant in the third quarter of 2022.
As you recall, probably in 2024 in particular, we were impacted by the fact that Bahiagás had committed to too much firm capacity relative to their demand, and they did have some demand disruptions. Bahiagás did have the opportunity to adjust for all that at the end of 2024 and entering 2025, so they've reduced their overall firm commitments. At the same time, Alvopetro's firm supply actually increased by 33%, so we're a much bigger portion of Bahiagás's market share now. The results have been a pretty good start to 2025. You can see our January and February production has averaged 2,375 barrels of oil equivalent per day, which is up 37% from the Q4 production that we just announced and the results that we announced yesterday.
Just to speak to our strategy as we move through 2025, again, we're looking to add more 100% working interest production to the mix, build our production capacity further, and be in a position that we can commit to even higher levels of firm next year and hopefully sell that gas through the rest of this year also on a flexible gas basis given how Bahiagás has readjusted their supply mix.
Okay. Just going into some detail on our results that were just released yesterday, the first thing here is the operating netback, which is those green bars that you see on the chart. This is one of those non-GAAP measures I referred to earlier. Operating netback is essentially our net operating income expressed on a per-unit basis. We express it in barrels of oil equivalent, or BOE. A reminder, it's computed at our realized sales price, which is at the top of the chart. We deduct off royalties in orange, production expenses in gray, and then the green bars again are our operating netback. In Q4, on the realized sales price, we did see a reduction of about 4% compared to Q3. Our natural gas sales price was $10.51 per MCF. That was also down about 4% from last quarter.
Our contracted price was essentially equivalent to Q3 in local currency, but with the devaluation of the Brazilian real relative to the US dollar. When we express that for reporting purposes in US dollar equivalent, there was a slight decrease there. Royalties, that's the orange bar, $2.15 per BOE in a quarter. That's an effective royalty rate of 3.4%, which is relatively consistent with past quarters. A reminder, our natural gas royalties are based on a reference price, which is more based on a value of raw and processed gas, so closer to Henry Hub. Relative to our gas price, it results in a lower effective royalty rate. On the production expenses, on a dollar basis, production expenses went up only about $19,000 in the quarter compared to last quarter, but we did have that 17% reduction in volume.
On a per BOE basis, we saw an increase. Overall, operating netback of $55.09, down $4.10 from last quarter. Again, if you compare that to the realized sales price, it's still a very high operating netback margin at 86%. We've said this before and we'll say it again. If you compare that to any other companies operating in South America or North America, these are very high netback margins. With our lower tax rate applicable in Brazil on our project with our tax incentives, it really allows us to generate significant funds flow from operations at these production levels. Moving on to funds flow, again, that's a non-GAAP measure closest to cash flow from operating activities, but before changes in working capital. This chart is just showing the change from Q3 to Q4.
There was a decrease of $2.9 million compared to Q3. The majority of that is that 17% reduction in sales volumes, slightly lower realized price, as I mentioned on the last slide. Then some higher G&A at Q4, just with some final year-end adjustments, and then slightly lower current tax. Funds flow from operations of $7 million in the quarter. Similarly, on net income, we saw a decrease of $4.9 million compared to Q3. Most of that was, or a lot of that was the lower operating netback with those lower sales volumes and lower realized prices, the G&A that we just talked about. The one big swing there is foreign exchange. We had a foreign exchange gain of $600,000 in Q3 compared to a loss of $2 million in Q4. That was a swing of $2.6 million.
Just a reminder, that is virtually all related to U.S. dollar denominated balances and foreign exchange losses recognized in our local Brazilian subsidiary on that fluctuation of the local currency relative to U.S. dollars. While we report in U.S. dollars, we still have to carry through that foreign exchange loss from the subsidiary on the consolidated statements. Slightly offsetting that is the lower current tax and lower deferred tax. Moving on to the balance sheet, these green bars here are showing our working capital, including all of our cash balances. This is since we came on production. Nice, strong balance sheet. We ended the year with $13.2 million of working capital, and still very strong working capital balances. Just a reminder, we are debt-free and have been since September of 2022.
Thank you. Just moving on to our dividend history here. In 2024, we paid dividends at a rate of $0.09 US per share per quarter. With the GSA gas sales agreement adjustments and the higher sales volumes that we're reflecting through Q1 here, we did announce yesterday an increase in the dividend for the first quarter of 2025 up to $0.10 US per share. If you consider this since inception of the dividend in the third quarter of 2021, we now will have paid $1.50 per share dividends out to shareholders since then, and that totals over $54 million US. Just to speak once again to our more disciplined capital allocation model where we're looking to balance, basically take half of our cash flows and invest that in organic growth, and then take the other half and return it to stakeholders.
This graph tries to kind of reflect that. The lines that you see on the chart here with the black dots are all the cash inflows that we've had or the funds flow from operations each quarter since our project came on stream. You can see in the fourth quarter cash inflows of $7 million. All the stacking bars show the cash outflows in each particular quarter and where that went to. The various shades of green are the stakeholder buckets, and the yellow stacking portion is the capital expenditures into organic growth. You can see in the fourth quarter, the sum of those did exceed funds flow from operations a little bit.
For all of 2024, what that looked like was 46% of our funds flow was spent on capital expenditures, and just under 49% was returned to stakeholders, with the remaining 5.5% effectively reflecting an increase in that cash and working capital position that Alison just walked you through. On the pie chart, you can see since inception, we've actually had cumulative funds flow from operations of over $163 million. 44% of that's been reinvested, 48% returned to stakeholders, and 7% of it's gone to that building cash and working capital for future flexibility. Late last year, we did announce an upgrade to our gas sales agreement. It became effective January 1, 2025. Like I said, we've increased our firm sales to Bahiagás by one-third.
We adjusted the quarterly price mechanism so that it's recalculated quarterly now, and it's based on Brent and Henry Hub benchmark prices. The net effect was, as of February 1, 2025, our realized natural gas price is over $10.50 US per Mcf. We did remove the old contractual floor and ceiling provisions that we had in our old contract, and given that we were pretty close to the ceiling, I think that's probably a net positive. We did also enhance the supply failure penalty mechanism so that it reduces our potential exposure. The take-or-pay mechanisms that ensure that Bahiagás is taking an appropriate amount of gas remain in place unchanged, and the updated contract does extend through to the end of 2035. The last point I'll make here is the really nice thing about all this infrastructure that we have is, one, it's 100% Alvopetro working interest.
It was all basically underpinned by the development of our Caburé assets. We are really well positioned now to bring new gas on a very low-cost basis because all the infrastructure and midstream part of our commercialization solution here is basically fixed costs. When you look at the drilling program that Adrian will walk through from Murucututu, it is all pipeline connected. We can bring it on immediately at virtually very small incremental cost.
We have recently completed our 2024 year-end reserve report, which highlights the advancements we made in 2024. This report shows that we have a total of 4.5 million BOE or barrels of oil equivalent proved reserves and 9.1 million BOE proved plus probable. We saw a 65% increase in the 1P and a 5% increase in the 2P volumes year over year and strong reserve replacement ratios.
This increase was the combined result of the redetermination that was done during the year and the strong production results from the Curaçao zone at . As you can see on the chart, our current enterprise value is about the same as the proved NPV 10 of just the Caburé asset alone. Production from the Caburé asset remains strong. This asset, which we are 56.2% working interest now, we began operating it in or we took over operating it in 2024 in August of 2024. In January of this year, we completed the installation of a compression system at this field, which serves to reduce the gathering line pressures and increase the production or deliverability of the asset.
As Corey mentioned, we're going to start a drilling program in this asset starting next quarter to add five more wells into the unit here. These are the black dots you can see on the bottom right-hand picture there. We're increasing the deliverability of this unit with those infill wells. Our other focus for 2025 is the continued development of the Curaçao zone at the Murucututu , which is just north of our Caburé asset. The 183-A3 well, which we put on production in September, has had excellent production and it's been performing above our expectations. Currently, we're drilling an up-dip well into the same structure, targeting 110 meters up-dip in the Curaçao zone, and intend to finish that well in the next month here. We're currently drilling that right now.
We have an additional follow-up location at the same pad as the well we are drilling now with the ability to drill another follow-up location later this year. We continue to evolve the multi-year development plan for this Murucututu asset. The picture on the left here shows the red lines and the red dots are pipelines and our pads and our wells that are existing. The white shows the multi-year development potential of what we can add both in the Curaçao and in the Gomo reservoirs of this field. This project can be funded organically and has the potential to get up to 20 million cubic feet a day. With success here, we feel we can more than double the size and value of the company with this opportunity alone.
Great. Thank you, Adrian.
On February 5th of 2025, we did announce our strategic entry back into the Western Canadian Sedimentary Basin. Our initial focus area here is in the Mannville heavy oil fairway, which sits just south of Lloydminster. These are multi-zone reservoirs that you can see characterized here with large amounts of original oil in place on a per mile or per section basis. I would say that this opportunity is quite consistent with our long-standing approach where we're trying to bring new ideas and new technologies to bear to look to ways to apply that technology to unlock new opportunities. I think this map does a good job of showing that evolution of technology in the Western Canadian Sedimentary Basin. You can see a bunch of simple vertical wells. That was kind of the original phase. You can see some horizontal wells that were drilled.
The new evolution of the technology is basically open hole multilateral wells. You are drilling a single leg into the formation. You case that. From there, you drill an open hole without casing a number of laterals. In our case, we are drilling six laterals per location. You are trying to maximize the reservoir contact with all that open hole contact with the reservoir. What we have done here is we have partnered with an established operator. They have got a great track record, I think. Our deal was to pay 100% of the first two earning wells to earn a 50% working interest in just over 19 sections of land. On a net basis, over 6,100 acres to ourselves. The future wells, obviously, will be funded 50/50 with a partner. We have already completed drilling the first two of those.
We've actually, in total, got over 15 km of open hole lateral in contact with the reservoir. We expect to have both those wells on production within the next 30 days. With success, I think this has an opportunity to have a big inventory of locations for us and really very quickly can become self-funding based on strong economics with strong IRRs, quick payouts. It really complements our Brazilian opportunity quite nicely and further supports our capital allocation model. In conclusion, certainly think Alvopetro continues to offer an extremely attractive investment proposition. We still continue to deliver very strong results off the back of very strong natural gas prices with industry-leading operating netbacks and operating netback margins. Obviously, we've started 2025 with some pretty strong production levels, which should lead to a nice Q1 for us.
We've got a clean balance sheet, strong free cash flow generation capacity, no debt, and all that helps support that capital allocation model that I've talked about. For value investors, like Adrian pointed out, we're trading at less than our 1P NAV right now, trading at less than a third of our 2P NAV. For yield investors, the upgraded dividend to $0.10 US per share translates into a dividend yield of over 12% at current share prices. For growth investors, I do think we have a very exciting organically funded capital program. If you look at the potential value that that can unlock, especially relative to our current enterprise value, I think 2025 is going to be an exciting year.
Now, considering that we can also deploy capital into high rates of return opportunities in both Brazil and Canada, I think it's a more exciting time than ever. With that, I'll stop sharing the presentation, and we'll start with the question and answer.
Okay. One of the questions that's come in is, can you remind us what the firm volume numbers again are with the new Bahiagás contract?
Yeah. We increase, and we'll get our units potentially mixed up here, but it's 300,000 cubic meters a day was the old amount, and we increased that to 400,000 cubic meters a day. It gets further complicated, unfortunately, by the fact that it's measured in heat equivalent units. If you look back, we worked through all this math in a previous press release that we put out. I'll maybe get Adrian to help me with some of the numbers. To meet our current firm obligations, it translates into is it 13?
10 cubic feet.
13 cubic feet.
I think so.
Thirteen million cubic feet a day, which if you translate that in, divide that by six into BOEs, it's a little over, call it 2,100 barrels of oil equivalent per day. Is that pretty close?
Yeah.
Okay. There are some questions on Canada. Why enter Canada, which is facing a tariff or lower netback compared to the high netback in Brazil? If you can comment on that.
Yeah. What we've always done is look for the best combinations of geological prospectivity and fiscal regime. We've looked for lots of opportunities out there. When we filtered all those, and you look, you got to remember we're doing this on a Canadian dollar basis. These Canadian opportunities actually stack up very well on a rate of return basis. Yeah, the absolute netback is lower. The operating netback margin's a bit lower, but the payouts and the IRRs are very compelling. I think it also was a nice complement. The reality in Brazil is we're dealing with projects that tend to have longer timelines, longer execution cycles. We sometimes deal with a service company environment that's challenging. I think the team's doing an amazing job of navigating all that. When you have success, it can generate great rates of return, which we're showing.
When we looked at adding inventory, the Canadian opportunity was just quite unique in that it had a completely different risk profile. The other reality is there's a ton of these opportunities available in Canada, whereas in Brazil, it's very competitive. It's just harder to build this type of inventory in a place like Brazil. It doesn't mean that we're not going to keep doing it in Brazil. We just felt like it was prudent to have two platforms to invest capital in. When we looked at all those opportunities globally, right in our backyard really stacks up quite nicely.
Okay. Staying on the Canada focus, if you can comment on future plans, are there plans to drill additional wells, etc.?
Yeah. Obviously, we're pretty happy with this. We just got started with this 40 days ago, and we've already drilled two wells. I think it's a good start. Obviously, we've got a partner here. We want to see the results from the initial wells. We'll obviously watch oil prices, and we'll work with our partner to develop a capital program for the second half of this year. I'd hope to be drilling at least two to four additional wells here this year. Hopefully, that's growing. I think after we get through that capital program, it would effectively be self-funding going forward with a reasonable level of success. We're pretty excited about this.
Okay. Some more specifics on Saskatchewan and the initial two wells that have been drilled. What is the expected initial production rate and hydrocarbon mix? How does the production type curve look and ultimate recovery?
Yeah. Just because these are the first two wells, we have not come out with a lot of definitive guidance on this. I think we will let the results speak for themselves. I think you can look at some other operators that are active in this area. Depending on which reservoir you are targeting and how thick it is, the results can range widely. Directionally, if the wells could come on between 100 and 120 barrels a day and cumulatively produce between 100,000 and 120,000 barrels of oil equivalent over the life of the wells, the rates of return are extremely compelling.
Sorry, just jumping around a little bit here. Will you give out 2025 guidance for activity and production in both countries?
Yeah. I think we kind of have, I guess, absent the Canadian stuff, we wanted to get through. I've just now directionally given you a range of guidance, I guess. I think the capital program will be quite flexible based on results and based on commodity prices.
There is a specific question around the Canadian firm. A question around, you paid 50% for, you paid for the first two wells for 50% working interest, but what happens on the additional wells? What is the treatment of the revenues going forward?
Yeah. This is kind of a typical firm in where we paid 100% Canadian, about roughly $ 4 million to drill those first two wells and complete them and equip them, which translates to just a little under $2.8 million US. We earn a 50% working interest in the production from those two wells. Every well going forward, we pay 50% of those wells, and we earn 50% of them. We have earned now over 19 sections of land on a gross basis.
The 2P production forecast is 15.9 million cubic feet a day in 2025. Is this dependent on demand, or have you already factored in some potential curtailments?
No, that would be certainly dependent on demand and the receipts from Bahiagás.
There's a question around hedging and foreign exchange. Have we looked at hedging foreign exchange gains and losses? We do evaluate that. The fact is it's been quite costly in Brazil. We have entered into some contracts in the past. They've been relatively expensive, but we do look at that all the time here. We will continue to do so.
The only other comment—oh, sorry.
No, no. Go ahead.
The only other comment I'd make is the foreign exchange volatility that Alison walked you through on the net income side. A lot of that relates to intercompany loans between our subsidiary in Brazil and Canada. Frankly, that earnings volatility would be probably difficult to manage, but it is an intercompany item. We're also trying to manage that through just making sure we have the right cash balances in Brazil. Obviously, we earn quite a bit higher interest rate, but we are subject to foreign exchange fluctuations. We're mindful of that. Lastly, with our upgraded gas sales agreement, one of the nice things about the quarterly adjustment mechanism is we have much quicker adjustments for commodity price movements as well as foreign currency movements.
Because it's reset every quarter, our exposure, we do have our price fixed in local currency, but now it's only for three months instead of six months. We have reduced that exposure, I would say.
Are there any further steps to come with the Caburé redetermination that was disputed?
Yeah. I think we've got a lot of disclosure in there about that as previously announced. We did go through an emergency arbitration procedure to, on an interim basis, validate that the expert decision's binding, which is what the agreements say. That does then go into a full-form arbitration. That is something that we'll be working through. It'll probably extend well into next year.
There was a question about the allocation of funds flow diagram that Corey went through earlier. If we looked at those percentages just since post-repayment of the credit facility. If you give me a second here. I did a quick—sorry. I did a quick look at that. If we look at since October of 2022, our funds flow has been about $94.5 million. 52% of that has been dedicated to CapEx. The other—45%, or actually close to 46%, in stakeholder returns. We can certainly provide that information going forward as well if that's useful to people. Just going back to the questions, there was a question about how many shares did we buy back in Q4. 126,000 shares were repurchased in Q4 and a total of 189,000 in 2024.
There's been 59,000 repurchased and canceled to the end of February of this year. Just a reminder, we do make those filings on SEDAR on a monthly basis that goes through all of those details. Staying on the share buyback front, there's a question around what are our thoughts on share buybacks in 2025 versus drilling new wells given we have a very strong balance sheet right now.
Yeah. I think this is something we look at every quarter. Right now, we're continuing forth with our normal course issuer bid kind of how we've been going. We increased the dividend. We would expect that to result in pretty close to the 50% of cash flow going to stakeholders in the first quarter. I think if we can increase our cash flows through the year, which is what our business plan would be, then we can have a discussion around where that incremental capital goes into those three buckets, whether it's more dividends, more share buybacks, or more capital program. Some of that will be a function of the results that we're generating with the capital and commodity prices as well. We're not going to lock ourselves into any one direction today.
A question on the dividend and the increase that was announced yesterday. Can you explain the rationale for increasing now versus waiting until Brazil production is over the 2022 high of close to 2,600 BOE per day?
Yeah. We were just trying to be consistent with our stated objective. With the increase in production, with the improvement in the gas sales agreement, I think our business has strengthened quite considerably, especially from a contractual perspective and then from an operational perspective. We built productive capacity with Caburé and the success in Murucututu. It felt like the right time to increase that base dividend.
There is a question here on Caburé that just came in. The company intends to add five more wells in the Caburé field. Will that increase the amount of reserves to be replaced and lead to the field being depleted faster?
Yeah. No, there is an element of building productive capacity. I think we do have the potential, especially with the northern wells that we're drilling, to potentially add some additional reserves. I think that's a fair comment that a good portion of this is to prolong and potentially increase the productive plateau of the field. Yeah.
Another question's come in. Are you looking at other opportunities beyond Brazil and Canada, or do these projects take up most of the capital allocation you are projecting?
We tend not to talk about business development details. Yeah, we are obviously keeping in tune with opportunities that might be available. We are pretty happy with the inventory of organic drilling opportunities that we've got in the mix right now. I think, especially, like I said, in Canada, there's a lot of lower-risk drilling opportunities that, frankly, just aren't being funded because of a scarcity of capital. I think we're well-positioned, be it there or elsewhere, to build our business.
Okay. With that, there's no other questions that have come in.
All right. Once again, thank you for your support, and thanks for tuning in. We look forward to updating you next quarter. If you have any questions in the interim, feel free to give any one of us a call. Thank you.